1. Field of the Invention
The present invention discloses a method for the reduction of the concentration of nitrogen oxides, NOx, in the products of combustion of a solid fossil fuel. The method comprises of creating a fuel rich combustion zone downstream of a primary excess air combustion zone in a combustor or furnace by introducing additional fuel into the downstream zone. The preferred embodiment of this invention is to inject into the downstream zone, aqueous liquid droplets containing dispersed solid fuel particles. Dispersion of the solid fuel particles is maintained by continuous mixing of the liquid and, if necessary, by the addition of a surfactant in the liquid-solid mixing vessel. Injection takes place in the furnace at a temperature range of 2000xc2x0 F. to 2500xc2x0 F. downstream of the main combustion zone where about 90% of the total fuel is burned under excess air conditions. The additional fuel injected in said zone results in slightly fuel rich temperature conditions, which converts the NOx to molecular nitrogen. For economic reasons, it is preferred to limit the additional fuel to 10% of the total fuel heat input to the furnace or boiler. However, the process has been found to be effective even with more than 30% of the total heat input injected in the downstream zone. Further downstream, sufficient additional air is introduced into the furnace to oxidize all unburned combustion gases and remaining fuel particles. Alternatively, the fuel rich NOx reduction zone can be limited to a central region of the furnace. The combustion gases containing excess air that surrounds this fuel rich zone will mix further downstream with the fuel rich gas and complete the combustion process. Specially designed atomized water droplet injectors are utilized to disperse and vaporize the droplets that contain the solid fuel particles throughout the gas temperature zone that yields optimum NOx reduction.
Alternatively, the fuel rich combustion zone can be produced by dispersion of liquid fuel droplets of varying size throughout the gas temperature zone at which NOx reduction is effective.
A third alternative method to produce the fuel rich combustion zone is to utilize pyrolysis gas, derived from coal or biomass produced in a separate vessel.
A fourth alternative method to introduce the additional fuel is to use pulverized coal particles or shredded biomass particles. The selection of the specific fuel and means for introducing this fuel is determined by fuel availability and economics and by combustor and boiler design considerations. The staged combustion method of this invention using these fuels and fuel injection methods can be combined with other NOx reduction processes to yield large overall NOx emission reductions.
2. Description of Prior Art
The combustion of fossil fuels under excess air conditions leads to the formation of NOx, a pollutant that leads to smog and acid rain over wide areas far removed from the combustion source, and it is especially a problem in urban environments. There are two sources of NOx, one is primarily formed during the combustion of solid fossil fuels, especially coal. The fuel bound nitrogen whose concentration is generally in the range of 1% by weight in the coal is the primary source of NOx in coal combustion. The three primary NOx precursors released in the combustion of fuel bound nitrogen are hydrogen cyanide, HCN, ammonia, NH3, and nitrogen oxide, NO. In fuel rich combustion, these three species are converted to nitrogen. Many researchers have measured the rate of destruction of these species under fuel rich conditions, (e.g. J. W. Glass and J. O. L. Wendt, xe2x80x9cMechanisms Governing the Destruction of Nitrogenous Species During Fuel Rich Combustion of Pulverized Coalxe2x80x9d, in Proceedings 19th Symposium (International) on Combustion, [The Combustion Institute, Pittsburgh, Pa. 1982] p.1243).
These rates can be used to estimate the time required to reduce these three species by a specific amount, such as a factor of 10. It was found that as the stoichiometric ratio approaches unity, i.e. as it proceeds from very fuel rich to leaner conditions, the concentration of NO predominates and the other two species are sharply reduced, (see for example, Y. H. Song, et.al., xe2x80x9cConversion of Fixed Nitrogen in Rich Combustionxe2x80x9d, in Proceedings 19th Symposium (International) on Combustion, [The Combustion Institute, Pittsburgh, Pa. 1982] p.53). Therefore, a conventional fuel lean combustor will produce almost completely NO species.
Calculations were performed for the time needed for a factor of 10 reduction of NO in a Western U.S. coal, using Glass"" reaction rates, for two fuel rich stoichiometric ratios of 0.5 and 0.7, i.e. 50% and 30% oxygen deficiency, respectively. Initial concentrations of NO at these stoichiometric ratios were taken from D. P. Rees, et.al., xe2x80x9cNO Formation in a Laboratory Pulverized Coalxe2x80x9d, in Proceedings 19th Symposium (International) on Combustion, [The Combustion Institute, Pittsburgh, Pa. 1982] p. 1305). It was found that temperature was by far the primary rate-governing factor, a factor of ten reduction required several seconds, while at 2500xc2x0 F., it required about 0.1 seconds, and at 3000xc2x0 F., about 0.01 seconds, for both 50% and 30% fuel rich stoichiometry. At the highest of these temperatures, however, thermal NOx begins to form in significant quantities under excess air conditions. Additionally, combustion with oxygen in excess of the amount required for stoichiometric combustion, which is required for all fossil fuels to minimize other pollutants, such as carbon monoxide, results in the formation of thermal NOx. Thermal NOx is formed from the reaction of nitrogen with oxygen in the combustion air, and its concentration rises substantially at temperatures above about 3000xc2x0 F.
The combustion gas velocity in the furnace region upstream of the superheater in large boilers is in the range of 20 to 25 feet per second. Therefore to create a,fuel rich zone in combustion gases containing excess oxygen at 2000xc2x0 F. would require a distance of 10""s of feet in the gas flow direction to achieve the factor of ten NO reduction. It thus appears that temperatures nearer to 2500xc2x0 F. are preferred to reduce the NO concentration in a thin gas slab perpendicular to the combustion gas flow direction. Based on the NO reduction calculation, it is only necessary to introduce the additional fuel at the base of a slab of gas having the proper temperature in a cross-section perpendicular to the gas flow direction. At 2500xc2x0 F., only 2 to 2-xc2xd feet in the gas flow direction are required to effect a high NO concentration reduction. While the calculation given here demonstrates the disclosed reburn approach, in actual practice a gas temperature range of 2000xc2x0 F. to 2500xc2x0 F. should be evaluated for optimizing the location of adding reburn fuel and the amount of reburn fuel needed for each specific boiler or furnace.
This additional fuel, or reburn fuel, produces a fuel rich zone downstream of the primary combustion zone of the furnace or boiler where the combustion gases contain an excess of oxygen. It is essential to implement the reburn process in as short a distance in the gas flow direction as possible. Furthermore, the reburn fuel should be introduced at the outer gas temperature boundary at which the NO reduction rate is optimum. This location for introducing the reburn fuel should be several feet away from the boiler walls in large boilers because the combustion gas temperature near the wall is lower and the reburn reaction rate is slower. The present invention discloses how this reburn fuel is preferably introduced into the boiler or furnace.
Coal is the primary fuel for utility boilers, and to efficiently burn it requires combustion at 3000xc2x0 F. or higher. Consequently, both fuel bound and thermal NOx form in high concentration, especially in large coal fired boilers used in electric utility power plants.
Several currently practiced technologies are used to control the emissions of NOx from fossil, and especially from coal, fired boilers. Among these control technologies are: Staged combustion in which initial fuel rich-combustion in or very close to the fuel injection zone is followed by excess air combustion immediately downstream of the initial combustion zone. There are a number of different staged combustion processes and system designs, depending on the boiler design. It has been observed that combustion under fuel-rich conditions converts the fuel bound NOx precursors to nitrogen, with the maximum reduction occurring at a stoichiometric ratio of 0.7, i.e. 70% of the combustion air needed for complete oxidation of all the fuel that is provided (see for example, J. W. Glass and J. O. L. Wendt, xe2x80x9cMechanism Governing the Destruction of Nitrogenous Species During Fuel Rich Combustion of Pulverized Coalxe2x80x9d, in Proceedings of the 19th Symposium (International) on Combustion, {The Combustion Institute, Pittsburgh, Pa. 1982}, p.1243), and ( Y. H. Song, et. al. xe2x80x9cConversion of fixed Nitrogen in Rich Combustionxe2x80x9d, in Proceedings of the 18th Symposium (International) on Combustion, {The Combustion Institute, Pittsburgh. Pa. 1982}, p.53 ).
In the most widely used staged combustion method, the main burners in large industrial or utility boilers are fitted with xe2x80x9clow NOx burnersxe2x80x9d that create a fuel rich zone at the lower end of the boiler. Final combustion air is introduced at one or more locations immediately downstream of the primary combustion zone of the boiler to complete combustion. One of the significant deficiencies with this process is that higher levels of unburned carbon are produced, which reduces the combustion efficiency and can make the fly ash unsuitable for recycling. The other deficiency is that chemical compounds can form in the fuel rich zone that corrode boiler metal tubes.
Another staged combustion process is applicable to slagging, cyclone combustors using pulverized coal with a fineness in the range of 70% passing through a 200 mesh (70 microns). Zauderer has measured NOx reductions (xe2x80x9cDemonstration of an Advanced Cyclone Coal Combustor, with Internal Sulfur, Nitrogen, and Ash Control for the Conversion of a 23 MMBtu/hr Oil Fired Boiler to Pulverized Coalxe2x80x9d Coal Tech Corp., August 1991, NTIS Documents DE92002587 and DE92002588, also xe2x80x9cStatus of Coal Tech""s Air-Cooled Slagging Combustorxe2x80x9d in Second Annual Clean Coal Technology Conference, September 1993, NTIS Document Conf-9309152) to the 0.3 to 0.4 lb/MMtu range (reported as NO2) in the boiler outlet stack under fuel rich conditions inside the combustor, where initial NOx concentrations were in the range of 0.8 to 1 lb/MMBtu under fuel lean conditions in the combustor. Final combustion air was introduced to the combustion gas at the combustor exit. Here again unburned carbon increased as the combustor stoichiometry decreased from 1 to 0.8, resulting in high levels of unburned carbon in the fly ash.
In summary, this staged combustion method of NOx control can achieve between 50% and 70% NOx reduction depending on the combustion system. However, the combustion efficiency loss and the carbon in the fly ash are two significant defects. Nevertheless, this method may be used in combination with other NOx control process to achieve substantial overall NOx reductions, if the carbon in the fly ash can be maintained below about 5%.
Another NOx control process is selective catalytic reduction, SCR, in which the relatively cold combustion gas effluent of several 100xc2x0 F. is passed over a catalyst coated bed in the presence of ammonia. The process can achieve over 90% NOx reduction and meet the most stringent NOx reduction standards. However, its capital cost is very high and the catalyst must be replaced at regular intervals, which results in a high maintenance cost.
Another process, generally called selective non-catalytic reduction, SNCR, involves the injection of various chemical compounds, primarily urea or ammonia, with or without various chemical additives, into the combustion gases in the boiler furnace at temperatures of about 1800xc2x0 F. to 2000xc2x0 F. where the NOx to N2 reaction is favored. This method can achieve in excess of 50% NOx reduction. However, it is essential to inject all the reagent into the proper gas temperature zone in order to minimize un-reacted NH3 carryover to the low temperature heat exchanger region where the NH3 reacts with sulfur gas to form liquid deposits on metal surfaces. Also, NH3 concentrations in the fly ash, as determined by ammonia odor, render the ash unsuitable for recycling. Finally, excess NH3 emissions in the stack gas plume can form a visible undesirable haze. Consequently, this method generally limits NH3 emissions downstream of the NOx reaction zone to 5 parts per million or less.
In order to assure injection of the reagent throughout the appropriate combustion gas temperature zone, Zauderer invented (U.S. Pat. No. 6,048,510) a droplet injector method in which droplets of varying size that contain the dissolved reagent, urea or ammonia, vaporize throughout the proper gas temperature zone of 1800xc2x0 F. to 2000xc2x0 F. This SNCR method has reduced NOx emission by about 50%. Zauderer combined it with the staged combustion method in a cyclone combustor to yield NOx emissions at the stack below 0.1 lb/MMBtu from untreated levels of 0.8 to 1.0 lb/MMBtu.
In the prior art, staged combustion, in which fuel lean combustion is followed by fuel rich combustion and final fuel lean combustion, has been called xe2x80x9creburnxe2x80x9d because the combustion gas is xe2x80x9cre-burnedxe2x80x9d downstream of the primary combustion zone. Two fuels have been mostly used for reburn, natural gas or pulverized coal.
In one case, natural gas is injected through one or more jets into the upper regions of a boiler""s furnace in quantities ranging from 5% to 20% of the total boiler heat input. The balance was pulverized coal injected in the primary combustion zone. For example, in reburn tests on a 158 MW electric output boiler, (xe2x80x9cEvaluation of Gas Reburning and Low NOx Burners on a Wall Fired Boilerxe2x80x9d, U.S. Department of Energy""s (DOE) Clean Coal Project, in Clean Coal Technology-Propram Update 1998, Report No. DOE-FE-0387, March 1999, pages 5-54 to 5-57) a combined total of 65% NOx reduction from an initial 0.73 lb/MMBtu was measured. Of this total, 37% was due to low NOx burners in the primary coal combustion zone, and the additional 43% reduction was due to reburn, using natural gas at 18% of the total heat input. In a second group of tests, the total reduction was 64% from an initial 0.73 lb/MMBtu of which 44% was due to low NOx burners and the additional 36% was due to natural gas reburn equal to 12.5% of the total heat input. This gas reburn method has two major drawbacks. One is the high cost of installing a pipeline to bring the gas to a coal fired power plant. Two is the substantially higher cost of natural gas compared to the coal it replaces. The economics of this process was marginal even when these tests were implemented at a time when the price of natural gas was in its historical range of $1 to $2 per million Btu range. At recent prices, approaching as high as $10 per million Btu, this process is uneconomical. Furthermore, the NOx reductions due to gas reburn is less than 50%, necessitating a third additional process to bring this boiler in compliance with the new EPA standard of 0.15 lb/MMBtu. This requires a total NOx reduction of 88% for this 158 MWe power plant.
Another DOE sponsored reburn project (xe2x80x9cDemonstration of Coal Reburning for Cyclone Boiler NOx Controlxe2x80x9d, U.S. Department of Energy""s (DOE) Clean Coal Project, in Clean Coal Technology-Program Update 1998, Report No. DOE-FE-0387, March 1999, pages 5-46 to 5-49) involved the use of pulverized coal as the reburn fuel for a 100 MWe cyclone fired boiler that uses crushed coarse coal as the primary fuel. Cyclone boilers have high NOx levels because the use of crushed coal requires combustion at excess air to burn the coarse coal particles. 50% to 55% NOx reductions to as low as 0.30 lb/MMBtu were measured with 29% to 35% of the fuel input due to the pulverized reburn coal. The drawback of this reburn process is its high capital cost ($43 to $66/kW) due to the need to add coal pulverizers to prepare the reburn coal. Pulverizers are not required for preparing the crushed coal used in cyclone fired boilers. As a result the cost of NOx reduction is high, ranging from $408 to $1065/ton removed, levelized over 10 years, for a 605 MWe and a 110 MW power plant, respectively. Here again an additional 50% reduction is needed to meet the new EPA standard of 0.15 lb/MMBtu. Furthermore, the initial NOx level in this 100 MWe boiler was relatively low compared to most crushed coal cyclone boiler. In other words, higher reductions would be needed in most cyclone boilers.
There are variations of this reburn process, such as using extremely fine (passing though a 325 mesh or less) pulverized coal for reburn. Also biomass has been used as a reburn fuel by other investigators according to a Department of Energy solicitation announcement (Solicitation: DE-PS26-00NT4077) with unreported results. However, the above two examples are representative of current reburn NOx control technology.
These prior art reburn processes also have a fundamental deficiency, namely the need to assure that the reaction to convert NOx to N2 occurs throughout the combustion gas temperature zone at which xe2x80x9creburnxe2x80x9d reaction is effective. The location where reburning would be effective in a large boiler is high up in the radiant furnace section, where the combustion gas temperature is low enough, typically about 2000xc2x0 F., or somewhat higher, so that the added xe2x80x9creburnxe2x80x9d fuel does not result in such a high temperature that thermal NOx is formed in the final combustion zone. Even in a relatively small utility boiler, such as a 50 MW unit, the furnace cross-section perpendicular to the gas flow direction is well over one hundred square feet. The problem with injecting natural gas jets or pneumatically injecting dry pulverized coal jets into this region is that it is impossible to uniformly cover the entire furnace cross-section with a uniform temperature xe2x80x9creburnxe2x80x9d combustion zone when using a reasonable small number of fuel injector jets. Even if the boiler water-wall were to be penetrated with a large number of openings to allow the installation of a large number of gas or coal injection jets, it would still be difficult to project the flame front to the center of the furnace. Therefore, in view of the high cost of natural gas, gas fuel reburn should only be used if the fuel source is very low in cost.
The present invention discloses a method for the reduction of the concentration of nitrogen oxides (NOx) in the products of combustion of a fossil fuel. The method consists of a staged combustion process in which a small quantity of additional fuel is injected into a furnace or boiler, downstream of the primary, excess air combustion zone, to render said injection zone slightly fuel rich and convert the nitrogen oxides into nitrogen gas. Additional air is added further downstream of said injection zone to complete final combustion under excess air conditions. Said injection zone is at a location in the furnace or boiler where the local gas temperature is low enough to prevent the formation of thermal nitrogen oxides from excessively high gas temperatures in the excess air, final combustion zone. Specifically, to assure uniform combustion from the added fuel throughout the reburn combustion zone, this invention is preferably practiced by injecting the added fuel as air or steam atomized liquid droplets of varying size, consisting of either oil-coal or coal-water slurry containing pulverized coal particles dispersed in the oil or water, which said solid particles being smaller than the droplets. The droplet injectors that are inserted in the furnace of a boiler at the outer edge of a temperature zone that is preferably in the range of about 2000xc2x0 F. to about 2500xc2x0 F., which is low enough to prevent increased formation of thermal NOx in the final combustion zone, yet high enough to assure complete combustion of any gas molecules or residual solid particles in a second zone where additional air is injected in order to complete combustion. In the preferred embodiment of the present invention, combustion of the solid fossil fuel particles takes place in the primary combustion zone under excess air conditions in order to minimize or totally eliminate any unburned carbon. Additional fuel, typically 5% to 20% of the total fuel input to the furnace or boiler, is introduced downstream of this primary combustion zone to result in a slightly fuel rich zone. This converts some of the NOx and its precursors into molecular nitrogen. Final combustion air is introduced into the furnace or boiler downstream of this slightly fuel rich zone to complete combustion under excess air conditions.
Alternatively, depending on the dimensions of the fuel rich combustion zone and the amount of fuel injected into this zone, there may be sufficient combustion gas regions containing excess air in the furnace, or boiler, outside the reburn zone to allow mixing with the fuel rich gases and complete combustion downstream of the fuel rich zone. In either case, the droplet size range are determined by the dimensions of the boiler being treated, while the dispersed solid fuel particle sizes are determined by the particle size needed to achieve rapid combustion after release from the vaporized droplets. Alternatively, fuel oil can be used for reburn in which case the droplets size range is selected to assure combustion throughout the gas zone being treated for NOx reduction, and lower cost hydraulic atomization is preferred over air or steam atomization. A further critical element of this invention is that in large furnaces or boilers, the droplets are injected in a flat fan pattern, perpendicular to the gas flow direction, which minimizes the number of injectors required. The present invention corrects this deficiency of non-uniform coverage of the NOx reduction reburn zone by preferably utilizing a droplet injector method similar to that disclosed in Zauderer""s invention of a Selective Non-Catalytic NOx Reduction, SNCR, process (U.S. Pat. No. 6,048,510, Apr. 11, 2000). In the present invention, droplets of varying size are used to introduce either a liquid fuel, such as oil, or solid fuel particles, such as pulverized coal or fine biomass particles, dispersed in liquid droplets of fuel, such as oil or water droplets, into the xe2x80x9creburnxe2x80x9d combustion zone downstream from the primary combustion zone. By using a droplet injector nozzle to create a droplet spray of varying size, the droplets will vaporize throughout the zone at which the staged reburn combustion is effective. This assures that the NOx to N2 reaction occurs throughout the combustion gas zone at which it is effective. A further benefit is that the number of injectors needed to implement this process is minimized to the point where existing access ports in a furnace or boiler can be used. This eliminates the need for adding costly new openings in the boiler wall. Therefore, the present invention allows reduction of NOx with the reburn method at very low capital and operating costs, when using pulverized coal for reburn in a pulverized coal fired plant, and at low capital cost, but with higher operating cost, when using oil for reburn.
For cyclone boilers that are fired with crushed coal, whose large particles are unsuitable for dispersion in oil or water, and which do not have on site pulverizers, this invention is practiced by partial gasification or pyrolysis of the crushed coal in a separate vessel, and injecting the gas through suitable air blown jets into said reburn zone. The residual char from gasification or pyrolysis is injected into the boiler""s primary cyclone combustors. Pyrolysis can also be used with shredded biomass fuel in any furnace or boiler, with the residual char injected in the primary combustion zone. Alternatively, some pulverized coal can be removed from the outlet of the pulverizers that feed a conventional pulverized coal fired boiler and used as the reburn fuel for NOx control. Similarly, shredded biomass can be injected pneumatically with air transport into said reburn zone. The specific approach selected will depend on the fuel type, fuel preparation, combustion type, and economics for the specific furnace or boiler being treated for NOx reduction. In most cases, the liquid droplet injector approach will be the preferred method for treating NOx reduction by the staged, reburn process. The one exception where pneumatic injection of the fuel is preferred would with biomass as the reburn fuel. Despite the deficiencies of gas fuel injection, there are situations where gas fuel or dry solid fuel are advantageous for staged reburn combustion for NOx control, namely, when the cost of the fuel is low or when secondary benefits outweigh the lesser efficiency of the gas or dry fuel for reburn. These cases, which are also part of the present invention, involve the use of dry, shredded biomass fuel that is injected pneumatically into the reburn combustion zone, or the use of pyrolysis gas prepared at the boiler site and derived from crushed coal or shredded biomass. The pyrolysis method is preferred for power plants operating with crushed coal fired, cyclone combustors, where the residual char from the pyrolysis process can be fired in the cyclone combustors. The advantage of using biomass, a renewable fuel, for reburn is that it reduces the overall emission of carbon dioxide, a greenhouse gas, which offers the user an additional NOx emission credit from the Environmental Protection Agency (EPA). The advantage of using pyrolysis gas from coal is that it eliminates the need for costly pulverizers in plants using crushed coal, cyclone combustors.